Field of the Invention
The present disclosure is directed to a biowaste treatment and recovery system, and a method for operation of the same. In one embodiment, the system comprises anaerobic digestion of a carbonaceous feedstock, production of an aqueous solution of hydrogen bromide and carbon dioxide, and recovery of hydrogen via electrolysis of the aqueous hydrobromic acid formed in the process. In at least one further embodiment, a hydrogen enriched biogas generator is incorporated into the present system to produce electricity and heat.
Description of the Related Art
Hydrogen sulfide, or H2S, is a smelly, corrosive and flammable environmental pollutant with toxicity comparable to cyanide. It is colorless and most commonly results from the anaerobic breakdown of organic sulfates, but may occur in volcanic gases from the hydrolysis of sulfide minerals. H2S is a broad spectrum poison which affects multiple parts of the body. It can block oxygen in mitochondria and stop cellular respiration. The body is able to detoxify it through oxidation to sulfate, so small levels of H2S can be tolerated.
H2S gives flatulence and rotten eggs their foul odor, and is very dangerous at low concentrations. It can be smelled at 5 parts per billion (“ppb”), begins to irritate the eyes at 10 ppm, and can no longer be smelled above 200 parts per million (“ppm”) because it paralyzes the olfactory nerve. The absence of smell can cause a false sense of safety. A single breath of 800 ppm H2S is enough to cause immediate collapse and will kill 50% of humans after 5 minutes.
H2S deactivates industrial catalysts, is corrosive to metal piping, and damages gas engines. It must be eliminated from industrial processes, or removed from gas before it is used, transported, or sold.
H2S is commonly found in natural gas, and is made at oil refineries and waste treatment facilities. In 2004 over 9 million tons of H2S was recovered from refineries and natural gas plants in the U.S. [Reference 30]. Biogas with 0.2-0.4% H2S is commonly produced in anaerobic digesters of animal waste. [Reference 31]. Natural gas with in excess of 5.7 milligrams of H2S per cubic meter of gas (0.0004 vol % H2S) is commonly called “sour gas” because of the rotten smell from its sulfur content. [Reference 32].
There are three major sources of hydrogen sulfide: the hydrodesulphurization of petroleum at refineries, the sweetening of sour-natural gas at treatment plants, and biogas from anaerobic digesters and landfills. Biogas is currently an insignificant source of H2S, but is growing due to the greater utilization of anaerobic digesters and landfill gas. In the U.S., refineries account for about 60% of H2S while natural gas treatment plants account for the remaining 40%. [Reference 33]. Other sources include coke ovens, paper mills, tanneries, gasification plants and coal-bed methane.
Refineries consume 65% of domestic hydrogen production for refining and sweetening oil. The petrochemical industry requires one pound of hydrogen (H2) to remove sixteen pounds of sulfur (S) as hydrogen sulfide (H2S) from refined petroleum products including gasoline, diesel, kerosene and fuel oils in a chemical process known as hydrodesulphurization. Using ethanethiol (C2H5SH) as the example sulfur compound common in petroleum products, the hydrodesulphurization reaction can be expressed as:C2H5SH+H2→C2H6+H2S  Eq. 2-1
The product H2S is collected and purified to yield a nearly 100% H2S stream. In 1996 more than 5 million tons of H2S waste was generated in the U.S. through hydrodesulphurization to remove sulfur compounds from crude oil. [Reference 34]. Each year the amount of sulfur in domestically refined crude oil increases.
As demand for liquid fuels increases and conventional oil reserves are depleted, there is an increasing need to sweeten ever more sour-crude oil, which results in the production of increasing amounts of hydrogen sulfide. A migration to coal-to-liquids technologies and coal gasification will further increase the amount of H2S generated, and require solutions to both remove H2S from hydrocarbon (synthesis-) gas streams and convert it to a benign substance.
Sour-gas is distributed all over the world with particularly large mega-field reservoirs in the Caspian Sea, Middle East, Canada, and Asia-Pacific, and smaller more distributed fields being common in the U.S. and other regions where extensive natural gas development has occurred. While sour gas is defined as having greater than 4 ppmv H2S, these sour-gas fields average anywhere from 10-30 wt % H2S, and their product sour natural gas must have its H2S removed prior to being delivered to market.
The United States has technically recoverable natural gas reserves estimated at up to 1,200 trillion cubic feet, but much of this gas is contaminated with H2S and thus considered low-quality. [Reference 36]. Removing large quantities of H2S from natural gas is costly, and as a result, large reserves of natural gas in the United States remain unused. About 17% of all presently exploited gas reserves in the United States have unacceptable levels 20 of H2S. [Reference 37]. Canada represents an even larger source of H2S as over 40% of the natural gas in Alberta is considered sour. [Reference 38].
Over 20% of ExxonMobile's reserve base, 10% of their proven reserves, and 20% of their undeveloped opportunities consist of sour-gas. [Reference 39]. New natural gas developments can have over 30 wt % H2S coming out of the ground, and the remaining natural gas reserves around the world are predominantly sour resources. [Reference 40]. Table 2-1 shows the typical gas components of two representative sour-gas wells.
Large sour-gas fields, like ones in North America and those near liquefied natural gas (LNG) terminals being built around the world, have the sulfur removed because the value of natural gas justifies it. Sour-gas has no value, and is in fact a liability, but sweetened natural gas is worth a lot, over $4/MMBtu in the U.S. at mid 2009 prices.
Other large sour-gas fields that produce oil will re-inject byproduct sour-gas back into the ground to maintain reservoir pressure, often because the sour-gas cannot be economically sweetened and conveyed to a market. Smaller sour-oil fields that do not practice reinjection, burn the gas in a flare to convert the dangerous H2S to less dangerous SO2. [Reference 41].
The most common local sources of H2S come from the anaerobic bacterial breakdown of organic matter in waste-water treatment plants, city landfills, and septic tanks. Many landfills and waste water treatment plants capture this H2S along with methane and CO2 in the form of biogas which is used for electricity and/or heat. While H2S is only 0.1-2% of the gas stream it must be removed before the biogas is used to prevent corrosion and sulfur emissions. The H2S concentration of biogas is dependent on the digested feedstock, which if high in sulfur can lead to greater concentrations of H2S. Table 2-1 shows typical components of biogas and landfill gas.
Coal-bed methane (CBM) occurs when methane produced from bacterial action adsorbs onto the surface of coal. In the past this methane was vented to the atmosphere prior to the extraction of coal for safety reasons, but now this resource is captured prior to mining. CBM is also produced from wells drilled down to unminable coal seams deep underground. CBM has a relatively low amount of H2S, but this still must be removed to meet pipeline specifications. Table 2-1 in the following section shows the typical components of such gases.
Over 100 trillion cubic feet of coal-bed methane reserves are deemed economically viable to produce out of a reserve base of 700 trillion cubic feet in the U.S. CBM currently provides about 10% of U.S. natural gas production.
Alberta and British Columbia in Canada are estimated to have 170 and 90 trillion cubic feet of coal-bed methane respectively. [Reference 42]. Australia and China are other countries that have developed some of these resources. CBM deposits are largely unexploited, but are found under approximately 13% of the Earth's surface where deep unminable coal seams occur. Therefore they represent an important low-carbon fossil energy resource for much of the world.
Refineries and natural gas treatment plants produce a nearly 100% H2S gas from the hydrodesulphurization of crude oil and sweetening of natural gas due to the processes they currently utilize. Sour-natural gas and biogas components vary immensely over different regions based on the characteristics of the source materials.
Table 2-1 shows some example sour gas mixtures. Sour-natural gas typically contains methane along with higher hydrocarbons such as ethane, propane, butane, pentane and heavier species. Carbon dioxide, steam and nitrogen are common contaminants as well. The amount of H2S can vary greatly, with some wells being over 50% H2S. [Reference 43].
Biogas from a digester is made up of near equivalent shares of methane and carbon dioxide with smaller amounts of ammonia and hydrogen sulfide. Coal-bed methane is mostly methane with varying amounts of carbon dioxide.
Landfill gas has a large fraction of nitrogen, and very small amounts of volatile compounds found in rubbish, including: toluene, dichloromethane, ethyl benzene, acetone, vinyl acetate, vinyl chloride, methyl ethyl ketone, benzene, xylenes, chloroethanes and chloroethylenes. These compounds are typically destroyed when the landfill gas is burned.
The predominant method of treating H2S involves a three step multistage process in which a sour gas stream is contacted with an amine scrubbing solution. The lean H2S amine solution absorbs H2S preferentially and is sent as a rich solution to a stripping column where it is heated to release absorbed H2S. This relatively pure H2S is then sent to a modified-Claus sulfur plant where ⅓rd of it is burned with air to create SO2, which is mixed with the remaining H2S to form steam and molten sulfur. This occurs in two or more catalytic stages. Sulfur is removed at each stage, and the final gas stream is flared to convert residual H2S into less harmful SO2.
The predominant method of removing H2S from sour natural gas streams is to absorb it into a mixture of amines using a contact tower.
Amines have a high affinity for H2S and preferentially absorb H2S into solution. Once the amines have absorbed H2S, and are considered spent, they are heated to liberate the absorbed H2S which is then captured as a concentrated gas. This is a temperature swing absorption process, and while it cleans the sour-gas stream, it does not treat the H2S which is sent to a modified-Claus plant for conversion to sulfur. The process requires heat and makeup amines must be added periodically, but the process is widely used and well understood.
Each has a different affinity for hydrogen sulfide and carbon dioxide at different temperatures. This allows two different amine plants to remove CO2 and then H2S or vice versa to get relatively pure streams of each.
In general, the removal of a pound of H2S requires 500 Btu of heat and 25 Btu of electricity, but these numbers can vary depending on the size of the amine plant. Regenerative amine plants are not deemed economical at capacities below 1,000 pounds of H2S per day. In such instances sacrificial methods are used which produce a product that is land filled.
Economics were obtained for a small amine system for treating a 250 thousand standard cubic feet per day (scf/day) with 0.6 vol % H2S. [Reference 45]. The total system costs $79,246 new, but would be available used for $40,000. This equipment was leased for $2,700 per month (including maintenance), amines cost $1,200 per month, and other expenses amounted to $400 per month for a total annual cost of $51,600.
The equipment removes 22 tonne of H2S a year. It costs $2,300 per tonne of H2S, which corresponds to costing 58 per MMBtu of natural gas sweetened. This H2S must still be treated as these amine plant costs are only for purifying it from a sour-natural gas stream.
The 100 year-old, multi-step Claus process is the most widely used method for treating hydrogen sulfide from crude oil, refined petro-products and raw natural gas desulphurization. The process requires a pure hydrogen sulfide stream, and consequently requires an amine scrubber to extract and purify the hydrogen sulfide from the sour gas.
This concentrated H2S is sent to a modified Claus plant for conversion into elemental sulfur and water with the overall reaction below. The reaction is a little endothermic, but the heat required for reaction is provided by the condensation of gaseous sulfur to liquid sulfur product:H2S(g)+½O2(g)→S(g)+H2O(g)  Eq. 2-2                ΔH°=+56 kJ/mol=3.5 kWht H2S(g)+½O2(g)→S(s)+H2O(g)  Eq. 2-3        ΔH°=−221 kJ/mol=−13.9 kWht         
The process occurs in several stages (usually three) in which a third of the sulfide gas stream is first oxidized by air or oxygen to form sulfur dioxide:H2S(g)+1.5O2(g)→SO2(g)+H2O(g)  Eq. 2-4                ΔH°=−518 kJ/mol=−32.6 kWht ΔG°=−495 kJ/mol        
This stream is mixed with the remaining two-thirds of the hydrogen sulfide stream and passed over multiple (usually three) catalyst beds to produce liquid sulfur via the Claus reaction:2H2S(g)+SO2(g)→3S(l)+2H2O(g)  Eq. 2-5                ΔH°=+686 kJ/mol=−43.2 kWht ΔG°=620 kJ/mol        
The first reaction is very exothermic and supplies most of the heat required for the endothermic catalytic 2nd reaction to produce sulfur. Thus overall there is minimal opportunity to utilize the heat of reaction.
Approximately 50% of the H2S is converted thermally in the burning process, while each catalytic section converts about 60% of the remaining H2S for a total removal of 97%.
A 100 tonne sulfur per day modified-Claus plant costs ˜$70 million installed with annual operating, maintenance and fixed charges amounting to $14 million a year. [Reference 46]. This corresponds to an operating cost of at least $380 per tonne of sulfur produced, or $360 per tonne of H2S treated. When the capital cost of the plant (7% WACC) at a realistic utilization rate (80%) and lifetime (15 years) is included the cost to treat a tonne of H2S rises to over $600. This corresponds to costing 15 per MMBtu of natural gas sweetened using the 0.6 vol % H2S amine plant example.
Claus plants are expensive to build and operate, require large land areas, and consume significant amounts of energy. Furthermore, they only treat 97% of the sulfide gases, and also require a tail gas unit to remove the remaining sulfide gases or convert them to less harmful sulfur dioxide. [Reference 47].
Enormous expenditure goes into removing H2S and converting it to sulfur, which is often not valuable enough to transport and accumulates around the desulphurization facility. When prices are low, the liquid sulfur is poured into large blocks to solidify for long term storage. Later, when prices justify, it is flaked, re-melted with steam and shipped to market. Sulfur is burned where needed to produce the more useful sulfuric acid. There are several dozen such blocks in Western Canada and the Rocky Mountain foothills next to sour gas production facilities. Some of these are visible from space. [Reference 49].
The combination of amine scrubber with modified-Claus plant, while effective, is prohibitively expensive at small scales and requires very large plants to be economical. Small sour natural gas sources must be connected to a central desulfurization facility through H2S corrosion resistant stainless steel pipelines, or have their H2S removed at the source by smaller amine plants and then transported by truck to the central facility. Both of these options are expensive, hindering the development of sour natural gas resources.
Occasionally petroleum refineries are forced to vent sour gas when pressure builds up to unacceptable levels. This vented gas is flared or burned up to consume the H2S and produce less toxic SO2, which then becomes acid rain. The flare also produces 100-150 additional unregulated pollutants, and wastes the energy captured in the H2S laced methane. Most refineries in the U.S. only flare in emergency situations, but around the world in less populated areas it is a normal means of disposing of gas.
Small oil-fields will also flare their sour-gas when stricter environmental regulations do not exist and economics do not justify recovering the gas. This occurs when oil is produced in areas without a gas infrastructure or nearby gas market, and is estimated to result in the release of 390 million tons of carbon dioxide a year which is about 1.5% of anthropogenic CO2 emissions. [Reference 51].
A further problem with flaring is that it often does not lead to complete combustion which puts exceptionally strong greenhouse gases and pollutants in the environment. The Alberta Research Council concluded that flares only burn 62% to 84% of the gases due to the effect of crosswinds and unsteady operation. [Reference 52]. While flaring does also occur for nonsour gases, in many situations in Africa, the former USSR, the Middle East and Asia it is the only solution for sour-gases.
Other methods of removing hydrogen sulfide gas fall into six categories: absorption, adsorption, chemical conversion, membrane permeation, condensation, and biofiltration.
The amine scrubber previously described is an absorption process. Other absorptive methods include treating with: metal oxides, chelated iron, quinone, vanadium, nitrite, alkaline salts, and other solvents, some of which are high-cost, non-regenerable reagents.
LO-CAT® is an iron-redox regenerative system that converts hydrogen sulfide into elemental sulfur. Raw gas is scrubbed with a catalyst solution to form sulfur and the treated gas exits the absorber. The catalyst is regenerated using air and returned to the absorber while elemental sulfur is filtered out of the solution. A 1 MM scf/day (28,317 m3/day) LO-CAT® system costs from $1-2 million depending on hydrogen sulfide concentration. The operating cost alone is $220 per tonne of sulfur removed.
In adsorptive processing, a material sorbs H2S onto its surface, and is then regenerated in a separate step by reducing the pressure or raising the temperature. This process is similar to absorption with amines, but occurs on the surface of a solid. Other absorptive media include zeolites, activated carbon, and other minerals. The disadvantage of adsorptive processing is that the absorptive media must be periodically replaced or recharged.
Chemical conversion is a common method for treating H2S from tail gas, landfill gas, anaerobic digesters, and other sources with a relatively low concentration and volume. A metal oxide, such as iron, zinc or sodium is placed in the path of a flowing gas stream contaminated with hydrogen sulfide. The metal oxide reacts with the hydrogen sulfide to produce water and a metal sulfide. Small H2S producers may scrub with hydrogen peroxide or NaOH to eliminate H2S very effectively.
A common example is iron oxide going to iron sulfide, which can then be disposed, or regenerated to produce sulfur and iron oxide again. SULFUR-RITE® is a solid scavenger process that converts hydrogen sulfide into iron sulfide. Raw sour gas saturated with water passes over a media bed to form iron sulfide and water with the sweetened gas exiting the system. A $41,000 system capable of treating 1 MM scf/day (28,317 m3/day) has operating costs of $6,600 per tonne of sulfur removed due to the cost of media.
Biological treatment requires passing low-level hydrogen sulfide containing gases through wet biologically active beds including: soil filters, biofilters, fixed film bioscrubbers, suspended growth bioscrubbers and fluidized bioreactors where the hydrogen sulfide is biologically oxidized. Biological treatment is most suitable for processing biogas from anaerobic digesters as the levels of hydrogen sulfide are low and will not kill the bio-organisms; however, treatment the rate is slow and the yields are low.
An emerging process under development by Argonne and KPM researchers is a molten copper reactor to separate hydrogen from H2S. In the reactor, H2S gas is bubbled though molten copper, which releases hydrogen and forms copper sulfide. The copper sulfide is reacted with air to recover pure copper, releasing a concentrated stream of sulfur dioxide, which is then reacted with water to form sulfuric acid. The copper is then reused with minimum losses. The reactions between the hydrogen sulfide, copper, copper sulfide and air release energy that help keep the system at 1,200° C. This process is interesting because it produces hydrogen, but may suffer from operation at such high temperatures.
In the U.S. there are 150 refineries processing over 18 million barrels of crude oil daily. The amount of hydrogen consumed and lost in desulphurization depends of the sulfur content of the crude oil. In 2005 roughly 550,000 tons of hydrogen went to desulphurization. Refineries can benefit from reducing or eliminating their need to continually consume fossil hydrogen for desulphurization, and are investigating ways to make the H2 they consume carbon neutral. [Reference 53].
Claus plants form water from the hydrogen used to remove sulfur. In 2005, 8.8 million tons of elemental sulfur was recovered from hydrodesulphurization domestically. In the recovery, 1.1 billion pounds of hydrogen reagent was lost in the formation of water.
Hydrogen has a minimum value of 1.45 times the price of natural gas, which at $7/MMBtu, gives the hydrogen a value of $10.15/MMBtu or $0.52 per lb. [Reference 54]. In 2005 the U.S. petrochemical industry lost $572 million worth of hydrogen in the desulphurization of its petroleum products. Globally 64 million tons of sulfur was recovered in 2005 from hydrodesulphurization, consuming 4 million tons of hydrogen valued at over $4 billion. H2S removal from sour gas and refineries is an $8 billion a year market.
The existing methods for H2S control are capitally intensive and require large scale implementations to be affordable. Because of the unfavorable economics, smaller natural gas wells must pipe their sour-gas from multiple wells through corrosion resistant and expensive stainless steel piping to a central desulfurization facility. Of 130 trillion cubic feet (TCF) of natural gas produced in the world, 5 TCF are flared and 15 TCF are reinjected into the ground corresponding to 18% of world natural gas demand. Alberta, Canada alone has 6500 flare stacks operating. [Reference 55]. Refineries and sour-oil field developers could make use of the 20 TCF of unused gas with a method for cleaning these gases to recover the natural gas and eliminate H2S and SO2 emissions.
Hydrogen is an essential chemical feedstock and processing agent used in oil refining, the chemical synthesis of ammonia, methanol, and other products, and for processing steel, glass and other specialty needs. [Reference 56]. In June 2008, the hydrogen market was valued at ˜$26 billion.
Annually the country can produce about 10.7 million metric tons of hydrogen as a chemical commodity consisting of ˜9 million metric tons captive, that is hydrogen consumed where produced, and ˜1.7 million metric tons of merchant, which is hydrogen stored, transported and sold for a variety of uses. [Reference 57]. 1.2 million metric tons of the merchant production was sent to refineries through over-the-fence arrangements in which the hydrogen is produced next door.
Refineries have driven most increases in domestic H2 demand recently as they require more hydrogen to meet tightened sulfur restrictions in diesel fuel and refine increasingly poor quality high-sulfur crude oil. It is interesting to note that the augmentation in domestic hydrogen capacity has benefited Americans by allowing domestic refineries to purchase lower quality crude oil, i.e. from Venezuela, at a discount that other countries cannot refine. The increased H2 capacity also allows a greater fraction of crude oil to be upgraded to lighter and more valuable gasoline and diesel while reducing the amount of undesirable heavy oil produced.
The increase in hydrogen demand at refineries has been tempered by reductions from the ammonia industry due to the high domestic price of natural gas. Since 1999 25 ammonia plants have closed permanently, corresponding to a 44% decline in domestic ammonia production between 2000 and 2006. The difference in production and demand has largely been made up through imports. [Reference 58].
Almost 2.3 million metric tons of hydrogen production capacity is currently dedicated to ammonia each year, corresponding to 20% of domestic hydrogen production, and 33% of dedicated hydrogen produced from natural gas. Worldwide ammonia uses 50% of global hydrogen produced. [Reference 59]. Methanol is another large consumer of hydrogen, with almost 200 thousand metric tons of hydrogen production capacity dedicated to it every year. Methanol capacity has declined by 86 percent between 2000 and 2006, and there are only two methanol plants currently operating in the U.S., again due to high natural gas prices.
The most common and least expensive method of producing hydrogen in the U.S. is Steam Methane Reforming (SMR) with production cost dependent on the price of natural gas. About 5% of the nation's natural gas demand is used to produce 6.8 million metric tons of hydrogen annually. [Reference 60]. This hydrogen is almost entirely for use in refineries and ammonia/methanol plants.
Water-electrolysis produces ˜500 tons of hydrogen annually serving niche markets, but is touted as the method for producing large quantities of H2 in the future. Other approaches that gasify, catalyze and decompose hydrogen-carriers are under investigation.
SMR is an endothermic, high-temperature (650-1,000° C.), high-pressure (600 psi) process in which methane is partially oxidized to syngas and reacted with steam in a water-gas shift reaction. It consumes natural gas, produces greenhouse gases, is only 70% energy efficient, and requires substantial capital due to catalysts, high process pressures and temperatures. [Reference 61]. Natural gas production is strained to meet growing domestic demand and its price has risen recently.
The cost of H2 from SMR is proportional to the cost of natural gas feedstock. If an SMR facility had no fixed cost associated with it, H2 would cost ˜1.45 times as much as natural gas on an energy basis because of production losses.
At the June 2008 average natural gas price of $12.80/MMBtu, SMR produces captive ‘at-the-gate’ H2 for $24.63/MBtu or $1.47/lb. [Reference 62]. This is almost three times as expensive as when many of the SMR plants were built, and resulted in many H2 intensive industries such as fertilizer and methanol production to move overseas. [Reference 63].
The quantity of H2 produced from water electrolysis is inconsequential, but despite the high energy requirements and cost of electrolyzing water, it remains the most common proposed solution for supplying large quantities of carbon neutral H2. Water-electrolysis is the most expensive H2 production process due to three unavoidable reasons: pretreatment of the water feedstock which must be de-ionized, high capital costs from expensive noble metal catalysts that are required, and the high electrical energy needed to dissociate water. It is uncertain where the significant amount of electricity required will come from, as the normally proposed solutions of new nuclear power plants and carbon capturing coal plants are projected to remain expensive.
In 2004, the National Academy of Science (NAS) reviewed the DOE hydrogen, fuel cell and infrastructure program, and recommended that the DOE explore alternatives to water electrolysis to produce low-cost renewable hydrogen. [References 64, 65]. In the same reference, without including distribution and storage costs, the NAS reported that, “due to high-energy requirements and capital-costs, one cannot meet the DOE (H2 cost) goals by electrolyzing water.”
Electricity is an expensive, high-value energy product. Hence, a process that reduces the amount of electrical power required to produce hydrogen is in line with expert recommendations. In contrast, HBr electrolysis requires less electricity than water, and readily accepts a contaminated feedstock, which if electrically conductive can act as a ‘slurry electrode’ to further reduce cell voltage. [Reference 66].
The least expensive hydrogen is that recovered as a byproduct of fossil-fuel processing. In the U.S. last year 3 million metric tons were produced from catalytic reforming at oil refineries. Most of the feedstock for this is naphtha which is a mixture of different hydrocarbons that results from refinery distillation operations. An additional 500 thousand metric tons were recovered from refinery off-gases through various purification processes.
Another interesting source of byproduct hydrogen is from chlor-alkali processes, or the production of chlorine for plastics and water treatment use. The process electrolyzes salt (NaCl) in a concentrated brine to produce hydrogen, caustic (NaOH) and chlorine. In 2006 almost 400 thousand metric tons of hydrogen was produced by the chlor-alkali industry.
Gasification is similar to SMR discussed above, but uses a heavier hydrocarbon feedstock such as oil or coal. The feedstock is partially burned with oxygen to produce hydrogen and carbon monoxide which is then reacted with water in a shift reaction to produce carbon dioxide and more hydrogen.
This process is used in refineries and chemical plants, but is penalized by high costs. The equipment must withstand high temperatures and harsh conditions, which means it must be robust, and the production of slag or solids from the ash components of the fuel leads to maintenance concerns. Nonetheless this is a promising technology for producing hydrogen.
As discussed in the prior work section, hydrobromic acid electrolysis requires significantly less energy than water electrolysis. The theoretical energy of the hydrogen-bromine bond is 46% of the hydrogen-oxygen bond, but the actual energy required to form hydrogen from hydrobromic acid azeotrope in an electrolyzer at room temperature is 40% of the actual energy to electrolyze water in practice. [Reference 67].
While the theoretical voltage for water electrolysis is 1.23 Volts, current electrolyzers operate at 2.0 Volts while new advanced electrolyzer designs are pushing this down to 1.8 Volts. Water can be electrolyzed at lower voltages if a lower current density is selected, but due to the high capital cost of water electrolyzers they are operated at less efficient conditions to minimize the total hydrogen production cost which includes fixed capital equipment charges. Operating at a higher current density increases the electricity cost per unit of hydrogen, but spreads the fixed capital cost across more total hydrogen production.
Water electrolyzers are expensive in part because they require catalysts on both the hydrogen cathode and oxygen anode. Hydrobromic acid electrolysis does not require catalysts at the cathode or anode. Only the reversible HBr fuel cell requires a light catalyst loading (about a tenth of oxygen anode loadings) on the bromine anode to generate power from H2 and Br2.
Hydrobromic acid electrolysis requires less energy and power than water electrolysis for a fixed quantity or rate of hydrogen production, and therefore is less expensive by the same margin. At a voltage 40% that of water's, the HBr electrolysis stack and power conversion equipment are correspondingly 60% smaller for a similar hydrogen production rate.
Unlike water, the energy required to electrolyze HBr is strongly dependent on temperature, and decreases at elevated temperatures. [Reference 68]. The open circuit decomposition voltage is significantly reduced at elevated temperatures.
The HBr solution coming from the H2S reactor is hot; at 80° C. its electrolysis commences at 0.6 Volts, or 16 kilowatt hours of electricity per kilogram of hydrogen produced (kWhe/kgH2). [Reference 69]. At a modest current density of 3 kA/m2 a polymer membrane electrolyzer operates at 0.8 Volts (21 kWhe/kgH2), but at 200° C. a pressurized graphite electrode cell will start to decompose HBr at 0.42 Volts (11 kWhe/kgH2). This is only 21% of the energy required to electrolyze water in state-of-the-art systems [Reference 70]., and 34% of the energy released from reacting hydrogen with oxygen. Thus it is possible to generate more electricity from reacting the hydrogen with oxygen, than is required to produce it from hydrogen bromide. Additional information on electrolyzing solutions of hydrobromic acid is presented below.
There are three large growing needs for H2: use in biofuel plants to increase cellulosic ethanol production, use in hydrogen-enriched combustion to reduce nitrogen oxide emissions, and use as a fuel for an evolving H2 economy. Along with these there will continue to be demand in refineries and nitrogen fertilizer plants.
Many biofuel production processes rely on ‘bugs’ to ferment a cellulosic or sugar-based feedstock into ethanol. The carbohydrates are broken down into alcohols and carbon dioxide which are purified and vented respectively. Other methods gasify feedstock to make carbon dioxide, carbon monoxide and hydrogen with these latter two components being combined over catalysts to produce liquid fuels.
In both processes, carbon dioxide can be reacted with hydrogen to form carbon monoxide and then hydrocarbons or alcohols through the sacrifice of further hydrogen to water.
Bio-feedstock can produce about three times as much liquid fuels when hydrogen is available. [Reference 71]. This corresponds with all a feedstock's carbon being converted to liquid hydrocarbons, and none going to carbon dioxide, which can increase biofuel productivity.
Natural gas fired power plants are a significant source of nitrogen oxide (NOx), especially in urban areas. Combustion turbines in particular are mostly found in urban areas and suffer from very high NOx emission rates, making them responsible for significant local nitrogen oxide pollution. A typical 115 MW gas turbine will produce 4,400 tons of NOx a year, which turns into ozone in the presence of volatile organic compounds, heat, and sunlight.
Some counties have been deemed ozone nonattainment areas because their ozone levels exceed health standards. [Reference 72]. In 2004, the EPA determined that 159 million Americans live in 474 counties with unsafe ozone smog levels. [Reference 73]. Ozone is a powerful oxidant that burns lungs and airways, causing them to become irritated, inflamed, and swollen. Ozone is linked to increased mortality, birth defects, asthma, respiratory problems, and increased hospitalization rates.
Since 1997, over 1,700 studies on the health and environmental effects of ozone have been published. [Reference 74]. Some conclusions from these studies include:                Exposure to ozone is related to increased mortality, and the inflame response it causes in lungs are particularly problematic for the elderly. Even low levels may cause chest pain and cough, aggravate asthma, reduce lung function, increase emergency room visits for respiratory problems, and lead to irreversible lung damage.        The amount of time children spend outside is directly proportional to higher incidences of asthma in high ozone areas, but not in areas of low ozone.        Women exposed to ozone during their second month of pregnancy have an increased risk of giving birth to babies with serious aortic artery and valve heart defects.        
H2 can be used to displace natural gas in 1 vol % H2-enriched natural gas combustion, which can reduce nitrogen oxide emissions by 15%. Burning 5 vol % H2 rich allows 50% NOx reductions over normal emission rates. The reduction occurs because hydrogen stabilizes natural gas burner flame stability, allowing leaner combustion at lower temperatures to reduce NOx formation.
Almost half of America's population lives in counties with ozone levels that exceed National Ambient Air Quality Standards. NOx reductions from H2-enriched natural gas combustion are valuable for the emission credit they create and can improve air quality in many urban environments.
There is growing political and environmental pressure to transition to a hydrogen economy, but there is no viable solution on how to make the large amounts of hydrogen required in a carbon neutral manner.
There is also a ‘chicken or egg’ problem in that the infrastructure to enable the hydrogen economy does not exist yet. Fortunately hydrogen can be used to make methanol or ethanol liquid fuels during the transition. Either way, renewable hydrogen is necessary to reduce fossil fuel dependence and power the vehicles of the proposed hydrogen, methanol or ethanol economies.
Prior to the emergence of an “H2 economy”, CO2 may be reacted with H2 over a catalyst to form methanol, which may be sold or dehydrated with sulfuric acid to form ethanol. [Reference 75]. This avoids transportation and storage issues with H2 and creates a useful chemical feedstock or fuel. Ethanol benefits from tax incentives, and can be used in the present fleet of vehicles. The CO2 may also be captured and disposed of to generate carbon credits.
Bromine is the only liquid nonmetallic element under standard conditions. There are two isotopes with 51% being the lighter 79 Dalton atom, and 49% being the heavier 81 Dalton atom. At room temperature, bromine's density is 3.12 g/cc and its partial pressure is 0.28 atm. It boils at 59° C. and freezes at −7° C. Bromine is very active chemically bringing tears to the eyes at 1 ppm and causing respiratory damage at 10 ppm.
Bromine was discovered independently by Antoine Balard and Carl Jacob Lowig in 1825 and 1826, respectively. It is named after the Greek word bromos for stench. Bromine is produced by reacting bromide, usually in the form of sodium bromide, with chlorine to produce bromine which is then removed as a vapor and condensed. Bromine may also be produced from the electrolysis of bromide rich brine.
Most bromine comes from Dead Sea deposits developed due to their very high bromine content exceeding 5,000 ppm. The U.S., China and U.K. produce bromine from saline aquifers with 300 to 5,000 ppm bromide. Seawater has 65 ppm bromide.
Bromine is not a rare element and its reserves are considered unlimited. Currently the U.S. has 725+ million lbs of bromine production capacity, but only makes ˜500 million lbs a year at $0.61 per bulk pound. Smaller quantities can cost from $1-3 per pound depending on if delivered by truck or barrel. The H2S bromination of the present disclosure process does not consume bromine, and is not expected to impact its cost.
Primary uses of bromine include flame retardants (40%), drilling solutions (24%), brominated pesticides such as methyl bromide for termites (12%), water treatment chemicals (7%), and other more specialized uses including photographic/other chemicals, rubber additives and pharmaceuticals (17%)
The use of bromine and bromination is an essential industrial process with well-known industrial safety, material and operating standards. A collection of major industrial companies and organizations concluded using bromine is safe. [Reference 76]. In 2001 the USGS report on bromine clearly stated bromine and its compounds are used safely, and will continue to be used. These results indicate that bromine and its compounds can be considered safe as a result of the established bromine safety standards and practices.
Earlier investigations provide a sound foundation for the inventive process of the present disclosure. These earlier efforts include extensive research on the bromination of sulfur dioxide, and the electrolysis of hydrogen bromide gas and hydrobromic acid solution.
Significant work went into understanding the reaction between sulfur dioxide (SO2), bromine (Br2) and water (H2O) to form sulfuric acid and hydrobromic acid. The reaction and its change in enthalpy at standard state (ΔH°) is displayed below:SO2(g)+2H2O(l)+Br2(aq)→2HBr(aq)+H2SO4(aq)  Eq. 1-4                ΔH°=−281 kJ/mol=−39 kWht/kgH2eqv2         
This reaction was proven to be favorable under efforts in the 1970's and 1980's to develop a hybrid water splitting cycle known as the Euratom Mark-13 process. [Reference 3]. In this process, product sulfuric acid was thermally decomposed to regenerate SO2 reactant along with oxygen and steam, as shown below:H2SO4(l)→SO2(g)+H2O(g)+O2(g)  Eq. 1-5                ΔH°=+275 kJ/mol=+37 kWht/kgH2eqv2         
Product HBr was electrolyzed to regenerate Br2 and produce hydrogen as previously discussed. A bench scale system built in 1983 successfully produced 50 liters per hour of hydrogen using the process. [Reference 4]. The reactions were proven to be favorable, but the process was not developed further as traditional hydrogen production methods from fossil fuels were more economical. [Reference 5].
As work on this hydrogen producing cycle was coming to a close, the first reaction of the cycle (Eq. 1-4) was applied to the treatment of SO2 emissions from coal-fired power plants. These power plants were coming under closer scrutiny for their air emissions, and technologies were needed to reduce their emissions to legislated levels. The Mark-13 process was renamed the ISPRA Mark-13A process, and applied to dilute SO2 gas streams with only a few percent SO2 by volume mixed in combustion flue gas (nitrogen, oxygen, carbon dioxide). In this adaptation, the sulfuric acid was concentrated, removed and sold instead of being thermally dissociated. [Reference 6].
In the 1980's work progressed from simulated flue gas streams in the laboratory to actual coal flue gases in the field. At the end of the decade a pilot plant was built and evaluated on a 30 MWt coal-fired boiler at the Sarras refinery in Italy. [Reference 7]. This pilot plant achieved 97% removal of SO2 emissions, nearly complete regeneration of bromine from HBr, and was considered a success.
Economic studies showed the process had significant operating cost advantages over competing limestone forced oxidation (LSFO) for SO2 removal, but no customers were found, and after several years of marketing the process, it was abandoned. The reasons the process was not adopted may be traced to 15% higher capital costs than LSFO, a move away from coal in Europe (particularly Italy where coal developments were halted), and a U.S.-centric conservative mentality that encouraged the adoption of domestically developed and proven LSFO. [Reference 8].
The reaction between bromine and SO2 was so favorable that the original researchers concluded the process could also be used for controlling H2S and carbon disulfide. The reaction and change in enthalpy at standard state (ΔH°) for the bromination of H2S in the presence of water to produce sulfuric acid (H2SO4) is displayed below:H2S(g)+4Br2(aq)+4H2O(l)→8HBr(aq)+H2SO4(aq)  Eq. 1-6                ΔH°=−707 kJ/mol=−24 kWht/kgH2eqv2         
The process was disclosed in a patent, but no work was ever published on the reactions. [Reference 9]. The original researchers concluded the process could not compete with existing processes in the inexpensive fossil energy environment of the 1990's, and did not pursue experimental investigations. [Reference 10].
Previous work on electrolyzing HBr can be divided into three broad categories: work done in Europe to electrolyze hydrobromic acid as part of the Mark 13 hybrid hydrogen production cycle, work done by the Japanese on gaseous HBr electrolysis again related to hydrogen production cycles, and work performed in the U.S. on reversible HBr fuel cells for use in energy storage applications. [Reference 11].
As part of developing the Mark 13 process for producing hydrogen, the electrolysis of hydrobromic acid was investigated and confirmed to occur at voltages significantly less than water electrolysis. Bipolar graphite electrodes were used with a platinized graphite cathode and smooth graphite anode. The noble metal catalyst platinum reduces the hydrogen overpotential at the cathode significantly. No platinum was used on the anode where exposure to bromine dissolves most catalysts. A diaphragm to separate the anode and cathode at the expense of a higher operating voltage was deemed unnecessary.
The decomposition voltage for a 50 wt % HBr solution at 373 K was found to be 0.75 and 1.0 Volts at 2 kA/m2 and 8 kA/m2 current density respectively. [Reference 12].
Japanese researchers investigated the gas phase electrolysis of HBr. They evaluated PTFE-bonded carbon and graphite-felt electrodes at modest current densities. The advantage of gas-phase electrolysis for thermo-chemical hydrogen production cycles were the lower theoretical decomposition voltage, the production of gaseous bromine, and the ability to directly electrolyze gaseous HBr from a high temperature production process. [Reference 13].
American researchers first developed hydrogen-halogen fuel cells in the 1960's. The kinetics were favorable and the reaction was found to be nearly reversible. This led to the research and development of hydrogen-chlorine and then hydrogen-bromine energy storage systems at General Electric and Brookhaven National Laboratories. Single cell stacks were used to evaluate different catalysts, catalyst loadings, and membrane types. Their work evaluated HBr decomposition voltages at a wide range of concentrations and modest range of temperatures. [Reference 14].
As well as confirming HBr electrolysis under 1 Volt at modest current densities, their work was particularly interesting for revealing the reversible nature of the hydrogen-bromine electrochemical couple. These researchers used polymer proton exchange membranes that benefited from low overvoltages, with the majority of losses being due to the internal cell resistance. Such cells could be operated in electrolysis mode to produce H2 and Br2 from HBr and electricity or in fuel cell mode to make electricity from H2 and Br2.
Rockwell International evaluated the electrolysis of hydrobromic acid at elevated temperatures as part of a hybrid cycle in which HBr was created from the exothermic bromination of cellulosic feedstock. Rockwell concluded that a 60 wt % HBr solution could be electrolyzed at only 0.75 Volts while operating at a 6 kA/m2 current density and 200° C.
HBr electrolysis is well understood from decades of work and related experience in the chlor-alkali industry which electrolyzes ‘brine’ or sodium chloride to produce over 13 million metric tons per year of chlorine. [Reference 19]. The electrolysis of brine is similar to electrolyzing HBr, thus the research objectives are centered on understanding the bromination reaction rates and yields for the thermo-chemical processing of hydrogen sulfide into HBr, and any necessary post-treatment steps for recovering bromine.
The ubiquitous and significant accomplishment of these groups was confirmation that HBr electrolysis could produce hydrogen for significantly less energy than water electrolysis. [Reference 15].
The underlying principle of the present inventive process is found in nature. Hydrogen sulfide from thermal vents in the deep ocean dissolves in salt water and is used by bacteria to form the base of a food chain that supports tubeworms and many other crustaceans. [Reference 16]. These worms tolerate high temperatures and sulfide concentrations, and use the red “plume” that contains hemoglobin to exchange compounds with the environment, e.g., hydrogen sulfide, carbon dioxide, oxygen, etc. The hydrogen sulfide is used by symbiotic bacteria held in an internal organ to make energy.
Methane clatharates form at high pressure and low temperature when water and methane freeze to form a solid. Methane clatharate deposits are very common in the deep ocean, and thought to contain several orders of magnitude more carbon than present in the atmosphere. [Reference 17].
In many parts of the ocean methane rises to the surface unreacted with saltwater from methane hydrates melting in ocean sediments. [Reference 18]. This occurs because methane is not soluble in water and is inert at moderate temperatures. No known organisms survive on methane.
The natural phenomenon of hydrogen sulfide dissolving and reacting with water while methane does not dissolve and bubbles to the surface illustrates the physical properties that allow an aqueous bromine solution to react with H2S while not affecting methane.
The present disclosure focuses on answering questions about the reaction of bromine with hydrogen sulfide to produce hydrobromic and sulfuric acids, and the decomposition of hydrobromic acid in an electrolyzer.
The results obtained by Applicant are categorized into three primary areas: understanding the theoretical expectations of the bromine desulphurization process; performing experiments to verify the process's efficacy; and estimating the process's economics to justify future work.
Theoretical performance evaluated by Applicant includes: calculating expected thermodynamic equilibrium; identifying potential reaction products and reaction mechanism; calculating theoretical decomposition potential of hydrobromic acid; and, analyzing process flow and energy balance.
Experimental testing performed by Applicant includes: confirming removal of H2S in excess of 99.9% with aqueous Br2 solution; evaluating reaction rates, kinetics, and/or mass transfer limits; identifying form of sulfur product and establish methods to remove and purify it; closing bromine and sulfur mass balances (99+% accounting); confirming efficacy of water scrubber to capture bromine/HBr vapors; identifying undesirable reactions between bromine, hydrocarbons and sulfur; evaluating electrolysis of hydrobromic acid in multi-cell stack; and, investigating effect of concentration on hydrobromic acid electrolysis.
Economic evaluation performed by Applicant includes: identifying process equipment requirements; process flow for prototype with energy and mass balance; estimating hydrogen production cost; and, constructing an integrated demonstration to convert H2S into hydrogen and sulfur.
Applicant seeks to overcome problems associated with hydrogen sulfide removal. In the course of testing, methods for reacting hydrogen sulfide with bromine and water are investigated. The principal issues to be overcome involve the potential side reactions of bromine with carbonaceous species such as methane, and the possibility that the H2S will not react with bromine. Secondary issues involve the effect of sulfur and/or sulfuric acid on HBr electrolysis and concerns with bromine material compatibility. A literature review suggests neither of these will be a problem.
The principal invention is a process capable of capturing the heretofore lost value of hydrogen sulfide by producing hydrogen and sulfuric acid from its treatment. The present inventive process has potential to simplify the treatment of this dangerous contaminant, increase natural gas and hydrogen supplies, and convert sulfur waste into useful sulfuric acid.
It would be beneficial to provide a method for regenerating hydrogen consumed in the hydrodesulphurization of petroleum products, provide net hydrogen from the sweetening of sour-natural gas and bio-gas, and reduce carbon dioxide emissions from steam methane reforming of natural gas into hydrogen.
Nationwide the process could increase exploitable domestic natural gas reserves by 168 Trillion Cubic Feet (TCF) by opening up presently undrilled sour-gas reserves. [Reference 20]. The opportunity is even greater in other regions, the UAE for instance has over 200 TCF of sour gas. [Reference 21]. The process can also increase supply by recovering H2S contaminated natural gas that is currently flared or re-injected into the ground around the world. [Reference 22].
Over 23 TCF of natural gas is consumed domestically each year. [Reference 23]. A supply/demand elasticity of 5 means this increased supply would reduce the cost of natural gas 3%, or 21¢/MBtu. [Reference 24]. This would reduce the cost to generate electricity in Natural Gas Combined Cycle (NGCC) plants by 2% to 11.76 ¢/kWh and save utilities and ratepayers $150 million a year in the State of California alone. [Reference 25].
If all 25 million tons of global man-made H2S emissions were treated with the present inventive process, 12 billion pounds of hydrogen, or 20% of the current global merchant hydrogen market would be produced. [Reference 26]. If consumed in a 50% efficient fuel cell or combustion turbine 72 billion kWh of energy would be produced, amounting to 0.4% of total global annual electricity demand. [Reference 27]. Use of the hydrogen and natural gas on-site where it is produced and sweetened respectively can improve air quality nationwide by reducing emissions of H2S and SO2 and provide transmission and distribution benefits. [Reference 28].
Using hydrobromic acid electrolysis to produce large quantities of hydrogen may encourage the adoption of electrical energy storage. Additional benefits stem from the large scale use of electrolyzers, which by shedding load or absorbing excess power can allow the grid to operate more efficiently by eliminating the need for a spinning reserve and allowing greater sourcing from intermittent renewable power.